Various procedures have been used to increase the flow of hydrocarbons from hydrocarbon-containing subterranean formations penetrated by wellbores. A commonly used technique involves perforating the formation to provide flow channels through which hydrocarbons flow from the formation to the wellbore. The goal is to leave the formation with maximum permeability or conductivity so that formation hydrocarbons flow to the wellbore with the least possible restriction. This can be accomplished by (1) preventing the entry of solids into the formation, which could decrease the permeability of the formation, (2) using well completion fluids that do not tend to swell and/or disperse formation particles contacted by the completion fluid, (3) preventing the entry of formation particles into the perforations, and (4) avoiding excessive invasion of wellbore fluids into the formation.
Specially formulated fluids are used in connection with completion and workover operations to minimize damage to the formation. Completion fluids are used after drilling is complete and during the steps of completion, or recompletion, of the well, such as cementing the casing, perforating the casing, and setting the tubing and pump. Workover fluids are used during remedial work in the well, such as removing tubing, replacing a pump, logging, reperforating, and cleaning out sand or other deposits.
Formation damage from solids and filtrate invasion may be minimized by treating the well in a near-balanced condition (wellbore pressure close to formation pressure). In high-pressure wells, however, it is often necessary to treat the well in both overbalanced or underbalanced conditions. If overbalanced, the treating fluids are designed to temporarily seal the perforations to prevent entry of fluids and solids into the formation, and if underbalanced, the treating fluids are designed to prevent entry of solids from the formation into the wellbore. Many such treating fluids are brine-based. Such overbalanced treating fluid is sometimes referred to as a "kill weight" fluid.
The brine composition for a particular application generally depends on four basic considerations: (1) brine concentration--to prevent clay swelling and dispersion, (2) fluid density--to provide formation pressure control, (3) viscosity--to achieve desired solids-carrying capacity, and (4) fluid loss control--to prevent excessive loss of fluid from the wellbore to the formation.
The brine concentration and fluid density are selected based on area experience and knowledge of well properties. Minimum brine concentration to prevent clay reactions in most formations is generally considered to be 5% to 10% for sodium chloride and 1% to 3% for calcium and potassium chloride brines.
Effective viscosity and fluid loss control for temperatures below about 350.degree. F. have been achieved by the addition of polymers to the brine. Various chemicals are added to obtain the desired effects, including for example carboxymethyl cellulose, hydroxyethyl cellulose, xanthan gum, guar gum, and hydroxypropyl guar gum.
In conjunction with polymers for fluid loss control, bridging agents have been added to the brine to form a bridge on the formation face to prevent fluid loss. The primary advantage of controlling fluid loss is the ability to prevent particle plugging of the near-wellbore permeability by placing the polymer-bridging particle "filter" on the formation face. Preferably the wellbore fluid (completion fluid and workover fluid) is designed so that solids bridge on the surface of the formation rock rather than inside the formation pores. This bridging, which is referred to as "filtration control," controls the escape of the liquid part of the fluid into the permeable formations. Excessive fluid loss from the workover and completion fluid may contaminate the producing formation, permanently displacing oil and gas and blocking production. This fluid loss problem is greatly increased at high temperatures and pressures encountered in deep wells.
While several completion and workover fluids for filtration control have been suggested, one promising composition uses brines containing water-soluble salts in particulate size, sometimes called "sized-salt." This technique has an advantage in that after the workover or completion operation is completed, the bridging material can be dissolved by circulating a flesh-water pill. The principal disadvantage is that polymer products used to suspend the salt particles and to supplement the bridging of salt particles are not temperature stable at temperatures above about 300.degree. F. These higher temperatures can cause breakdown of viscosifiers and filtration control additives. For example, starch and xanthan gum degrade at about 225.degree. F. to 250.degree. F., carboxymethyl cellulose and guar gum degrade at about 250.degree. F. to 300.degree. F., and lignosulfonates begin to degrade at about 250.degree. F. and are particularly unstable above about 325.degree. F. Without adequate filtration control, formation damage can result.
The search for oil and gas has led to the drilling of deeper wells in recent years. Because of the temperature gradient in the earth's crust, deeper wells have higher bottomhole temperatures. A good workover and completion fluid should be rheologically stable over the entire range of temperatures to which it will be exposed, in order to suspend the particulate filtration and bridging additives. In deep wells, this can exceed 450.degree. F.
There is a need for an improved wellbore fluid, particularly for completion and workover operations in overbalanced conditions, that can substantially reduce fluid loss into reservoirs above 350.degree. F.